UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
___________________________________________________
FORM 10-Q
þ
 
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
 
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2013
OR
o
 
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
 
FOR THE TRANSITION PERIOD FROM __________TO __________ 

Commission file number: 001-35742
ALON USA PARTNERS, LP
(Exact name of Registrant as specified in its charter)
___________________________________________________

Delaware
 
46-0810241
(State of incorporation)
 
(I.R.S. Employer
 
 
Identification No.)
12700 Park Central Dr., Suite 1600, Dallas, Texas 75251
(Address of principal executive offices) (Zip Code)

(972) 367-3600
(Registrant’s telephone number, including area code)
___________________________________________________

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Yes  þ No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act:
Large accelerated filer o
Accelerated filer o
Non-accelerated filer þ
Smaller reporting company o
 
 
Indicate by check whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ
The number of the Registrant’s common limited partner units outstanding as of August 1, 2013, was 62,502,467.

 
 



TABLE OF CONTENTS

 
 
 
 
 
EX-31.1 CERTIFICATION OF CEO PURSUANT TO SECTION 302
EX-31.2 CERTIFICATION OF CFO PURSUANT TO SECTION 302
EX-32.1 CERTIFICATION OF CEO AND CFO PURSUANT TO SECTION 906


Table of Contents

PART I. FINANCIAL INFORMATION

ITEM 1.
FINANCIAL STATEMENTS

ALON USA PARTNERS, LP AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(dollars in thousands)
 
June 30,
2013
 
December 31,
2012
 
(unaudited)
 
 
ASSETS
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
26,684

 
$
66,001

Accounts and other receivables, net
129,330

 
104,119

Accounts and other receivables, net - related parties
12,933

 
14,519

Inventories
54,006

 
57,034

Prepaid expenses and other current assets
2,649

 
6,868

Total current assets
225,602

 
248,541

Property, plant and equipment, net
473,992

 
483,061

Other assets, net
30,221

 
31,821

Total assets
$
729,815

 
$
763,423

LIABILITIES AND PARTNERS’ EQUITY
 
 
 
Current liabilities:
 
 
 
Accounts payable
$
204,456

 
$
202,121

Accrued liabilities
43,619

 
42,218

Current portion of long-term debt
2,500

 
2,500

Total current liabilities
250,575

 
246,839

Other non-current liabilities
43,985

 
42,047

Long-term debt
242,812

 
292,811

Total liabilities
537,372

 
581,697

Commitments and contingencies (Note 11)

 

Partners’ equity:
 
 
 
General Partner

 

Common unitholders - Public (11,502,467 and 11,500,000 units issued and outstanding at June 30, 2013 and December 31, 2012, respectively)
35,416

 
33,438

Common unitholders - Alon Energy (51,000,000 units issued and outstanding at June 30, 2013 and December 31, 2012, respectively)
157,027

 
148,288

Total partners’ equity
192,443

 
181,726

Total liabilities and partners' equity
$
729,815

 
$
763,423


The accompanying notes are an integral part of these consolidated financial statements.
1

Table of Contents

ALON USA PARTNERS, LP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(unaudited, dollars in thousands except per unit data)

 
For the Three Months Ended
 
For the Six Months Ended
 
June 30,
 
June 30,
 
2013
 
 
2012
 
2013
 
 
2012
 
 
 
 
Predecessor
 
 
 
 
Predecessor
Net sales (1)
$
865,694

 
 
$
823,769

 
$
1,669,861

 
 
$
1,708,043

Operating costs and expenses:
 
 
 
 
 
 
 
 
 
Cost of sales
767,322

 
 
672,270

 
1,417,525

 
 
1,460,164

Direct operating expenses
27,314

 
 
25,073

 
57,736

 
 
47,743

Selling, general and administrative expenses
5,065

 
 
3,909

 
12,730

 
 
7,754

Depreciation and amortization
11,243

 
 
11,424

 
23,307

 
 
23,390

Total operating costs and expenses
810,944

 
 
712,676

 
1,511,298

 
 
1,539,051

Operating income
54,750

 
 
111,093

 
158,563

 
 
168,992

Interest expense
(8,970
)
 
 
(5,683
)
 
(18,362
)
 
 
(10,757
)
Interest expense - related parties

 
 
(4,266
)
 

 
 
(8,533
)
Other income (loss), net
14

 
 
(4
)
 
18

 
 
17

Income before state income tax expense
45,794

 
 
101,140

 
140,219

 
 
149,719

State income tax expense
473

 
 
917

 
1,373

 
 
1,420

Net income
$
45,321

 
 
$
100,223

 
$
138,846

 
 
$
148,299

Earnings per unit
$
0.73

 
 


 
$
2.22

 
 
 
Weighted average common units outstanding (in thousands)
62,502

 
 


 
62,502

 
 
 
___________
(1)
Includes sales to related parties of $156,043 and $148,171 for the three months and $297,942 and $298,734 for the six months ended June 30, 2013 and 2012, respectively.


The accompanying notes are an integral part of these consolidated financial statements.
2

Table of Contents

ALON USA PARTNERS, LP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited, dollars in thousands)
 
For the Six Months Ended
 
June 30,
 
2013
 
 
2012
 
 
 
 
Predecessor
Cash flows from operating activities:
 
 
 
 
Net income
$
138,846

 
 
$
148,299

Adjustments to reconcile net income to cash provided by operating activities:
 
 
 
 
Depreciation and amortization
23,307

 
 
23,390

Non-cash interest on subordinated debt - related parties

 
 
8,533

Amortization of debt issuance costs
990

 
 
925

Amortization of original issuance discount
251

 
 

Changes in operating assets and liabilities:
 
 
 
 
Accounts and other receivables, net
(25,211
)
 
 
(10,192
)
Accounts and other receivables, net - related parties
1,586

 
 
(248
)
Inventories
3,028

 
 
(21,453
)
Prepaid expenses and other current assets
4,219

 
 
951

Other assets
553

 
 
(655
)
Accounts payable
2,335

 
 
31,808

Accrued liabilities
1,401

 
 
(220
)
Other non-current liabilities
1,938

 
 
6,005

Net cash provided by operating activities
153,243

 
 
187,143

Cash flows from investing activities:
 
 
 
 
Capital expenditures
(9,157
)
 
 
(11,042
)
Capital expenditures for turnarounds and catalysts
(4,819
)
 
 
(8,062
)
Net cash used in investing activities
(13,976
)
 
 
(19,104
)
Cash flows from financing activities:
 
 
 
 
Distributions paid to unitholders
(23,579
)
 
 

Distributions paid to unitholders - Alon Energy
(104,550
)
 
 

Net cash payments to partner - Alon Energy

 
 
(216,886
)
Deferred debt issuance costs
(205
)
 
 
(2,400
)
Revolving credit facility, net
(49,000
)
 
 
(43,000
)
Payments on long-term debt
(1,250
)
 
 

Net cash used in financing activities
(178,584
)
 
 
(262,286
)
Net decrease in cash and cash equivalents
(39,317
)
 
 
(94,247
)
Cash and cash equivalents, beginning of period
66,001

 
 
135,945

Cash and cash equivalents, end of period
$
26,684

 
 
$
41,698

Supplemental cash flow information:
 
 
 
 
Cash paid for interest, net of capitalized interest
$
17,912

 
 
$
8,084

Cash paid for income tax
$
1,373

 
 
$
2,597


The accompanying notes are an integral part of these consolidated financial statements.
3

Table of Contents

ALON USA PARTNERS, LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited, dollars in thousands except as noted)
(1)
Basis of Presentation
As used in this report, the terms "Alon" or the "Partnership" refer to Alon USA Partners, LP, one or more of its consolidated subsidiaries or all of them taken as a whole. References in this report to "Alon Energy" refer collectively to Alon USA Energy, Inc. and any of its subsidiaries other than Alon USA Partners, LP, its subsidiaries and its general partner. The information presented in this Quarterly Report on Form 10-Q contains the unaudited combined financial results of Alon USA Partners, LP Predecessor ("Predecessor"), our predecessor for accounting purposes, for the three and six months ended June 30, 2012. The unaudited consolidated financial results for the three and six months ended June 30, 2013 include the results of operations for the Partnership. The balance sheets as of June 30, 2013 and December 31, 2012 present solely the consolidated financial position of the Partnership.
Alon is a Delaware limited partnership formed in August 2012 by Alon Energy and its wholly-owned subsidiary Alon USA Partners GP, LLC (the "General Partner"). On November 26, 2012, the Partnership completed its initial public offering (the "Offering") of 11,500,000 common units representing limited partner interests.
After completion of the Offering, Alon Energy contributed to the Partnership its equity interests in Alon USA, LP and Alon USA Refining, Inc. Prior to completion of the Offering, the assets, liabilities and results of operations of the aforementioned assets related to our Predecessor.
These consolidated financial statements and notes are unaudited and have been prepared in accordance with United States generally accepted accounting principles (“GAAP”) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the Securities Exchange Act of 1934. Accordingly, they do not include all of the information and notes required by GAAP for complete consolidated financial statements.
In the opinion of the General Partner’s management, the information included in these consolidated financial statements reflects all adjustments, consisting of normal and recurring adjustments, which are necessary for a fair presentation of Alon’s consolidated financial position and results of operations for the interim periods presented. All significant intercompany balances and transactions have been eliminated in consolidation. Certain prior year balances may have been aggregated or disaggregated in order to conform to the current year presentation. The results of operations for the interim periods are not necessarily indicative of the operating results that may be obtained for the year ending December 31, 2013.
The consolidated balance sheet as of December 31, 2012 has been derived from the audited financial statements as of that date. These unaudited consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in Alon’s Annual Report on Form 10-K for the year ended December 31, 2012.
New Accounting Standards
Effective January 1, 2013, Alon adopted Accounting Standards Update (“ASU”) No. 2011- 11, Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities and ASU No. 2013- 01, Balance Sheet (Topic 210): Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities issued by the Financial Accounting Standards Board (“FASB”). These updates require an entity to disclose both gross information and net information of recognized derivative instruments, repurchase agreements and securities borrowing and lending transactions offset in the consolidated balance sheet. The updated guidance was applied retrospectively, effective January 1, 2013. The adoption concerns disclosure only and did not have any financial impact on the consolidated financial statements.
(2)
Fair Value
Alon must determine fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. As required, Alon utilizes valuation techniques that maximize the use of observable inputs (levels 1 and 2) and minimize the use of unobservable inputs (level 3) within the fair value hierarchy. Alon generally applies the “market approach” to determine fair value. This method uses pricing and other information generated by market transactions for identical or comparable assets and liabilities. Assets and liabilities are classified within the fair value hierarchy based on the lowest level (least observable) input that is significant to the measurement in its entirety.
The carrying amounts of Alon’s cash and cash equivalents, receivables, payables and accrued liabilities approximate fair value due to the short-term maturities of these assets and liabilities. The reported amounts of long-term debt approximate fair value. Derivative financial instruments are carried at fair value, which is based on quoted market prices. Derivative instruments and the Renewable Identification Numbers ("RINs") obligation are the only financial assets and liabilities measured at fair value on a recurring basis.

4

Table of Contents
ALON USA PARTNERS, LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited, dollars in thousands except as noted)


The RINs obligation represents the period-end deficit for the purchase of RINs to satisfy the requirement to blend biofuels into the products Alon has produced. Alon's RINs obligation is based on the RINs deficit and the price of those RINs as of the balance sheet date. The RINs obligation is categorized as Level 2 of the fair value hierarchy and is measured at fair value using the market approach based on quoted prices from an independent pricing service.
The following table sets forth the assets and liabilities measured at fair value on a recurring basis, by input level, in the consolidated balance sheets at June 30, 2013 and December 31, 2012, respectively:
 
Quoted Prices in
Active Markets
For Identical
Assets or
Liabilities
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 
Consolidated
Total
As of June 30, 2013
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
Commodity contracts (futures and forwards)
$
181

 
$

 
$

 
$
181

Liabilities:
 
 
 
 
 
 
 
Fair value hedge

 
1,925

 

 
1,925

RINs obligation

 
8,016

 

 
8,016

 
 
 
 
 
 
 
 
As of December 31, 2012
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
Commodity contracts (futures and forwards)
$
2,365

 
$

 
$

 
$
2,365

Liabilities:
 
 
 
 
 
 
 
Fair value hedge

 
327

 

 
327

(3)
Derivative Financial Instruments
Commodity Derivatives — Mark to Market
Alon selectively utilizes commodity derivatives to manage its exposure to commodity price fluctuations and uses crude oil and refined product commodity derivative contracts to reduce risk associated with potential price changes on committed obligations. Alon does not speculate using derivative instruments. Credit risk on Alon’s derivative instruments is substantially mitigated by transacting with counterparties meeting established collateral and credit criteria.
Fair Value Hedge
Fair value hedges are used to hedge price volatility in certain refining inventories and firm commitments to purchase inventories. The level of activity for fair value hedges is based on the level of operating inventories. The gain or loss on a derivative instrument designated and qualifying as a fair value hedge, as well as the offsetting loss or gain on the hedged item attributable to the hedged risk, is recognized currently in income in the same period.
As of June 30, 2013, Alon has accounted for certain commodity contracts as fair value hedges with contract purchase volumes of 333 thousand barrels of crude oil with remaining contract terms through May 2019.

5

Table of Contents
ALON USA PARTNERS, LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited, dollars in thousands except as noted)


The following table presents the effect of derivative instruments on the consolidated statements of financial position:
 
As of June 30, 2013
 
Asset Derivatives
 
Liability Derivatives
 
Balance Sheet
 
 
 
Balance Sheet
 
 
 
Location
 
Fair Value
 
Location
 
Fair Value
Derivatives not designated as hedging instruments:
 
 
 
 
 
 
 
Commodity contracts (futures and forwards)
Accounts receivable
 
$
909

 
Accrued liabilities
 
$
(728
)
Total derivatives not designated as hedging instruments
 
 
$
909

 
 
 
$
(728
)
 
 
 
 
 
 
 
 
Derivatives designated as hedging instruments:
 
 
 
 
 
 
 
Fair value hedge
 
 
$

 
Other non-current liabilities
 
$
(1,925
)
Total derivatives designated as hedging instruments
 
 

 
 
 
(1,925
)
Total derivatives
 
 
$
909

 
 
 
$
(2,653
)
 
As of December 31, 2012
 
Asset Derivatives
 
Liability Derivatives
 
Balance Sheet
 
 
 
Balance Sheet
 
 
 
Location
 
Fair Value
 
Location
 
Fair Value
Derivatives not designated as hedging instruments:
 
 
 
 
 
 
 
Commodity contracts (futures and forwards)
Accounts receivable
 
$
2,365

 
 
 
$

Total derivatives not designated as hedging instruments
 
 
$
2,365

 
 
 
$

 
 
 
 
 
 
 
 
Derivatives designated as hedging instruments:
 
 
 
 
 
 
 
Fair value hedge
 
 
$

 
Other non-current liabilities
 
$
(327
)
Total derivatives designated as hedging instruments
 
 

 
 
 
(327
)
Total derivatives
 
 
$
2,365

 
 
 
$
(327
)
The following tables present the effect of derivative instruments on Alon’s consolidated statements of operations:
Derivatives in fair value hedging relationships:
 
 
 
Gain (Loss) Recognized in Income
 
 
 
For the Three Months Ended
 
For the Six Months Ended
 
 
 
June 30,
 
June 30,
 
Location
 
2013
 
 
2012
 
2013
 
 
2012
 
 
 
 
 
 
Predecessor
 
 
 
 
Predecessor
Fair value hedge
Cost of sales
 
$
(4
)
 
 
$

 
$
(1,598
)
 
 
$

Total derivatives
 
 
$
(4
)
 
 
$

 
$
(1,598
)
 
 
$


6

Table of Contents
ALON USA PARTNERS, LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited, dollars in thousands except as noted)


Derivatives not designated as hedging instruments:
 
 
 
Gain (Loss) Recognized in Income
 
 
 
For the Three Months Ended
 
For the Six Months Ended
 
 
 
June 30,
 
June 30,
 
Location
 
2013
 
 
2012
 
2013
 
 
2012
 
 
 
 
 
 
Predecessor
 
 
 
 
Predecessor
Commodity contracts (futures & forwards)
Cost of sales
 
$
(1,001
)
 
 
$
2,041

 
$
6,650

 
 
$
5,176

Commodity contracts (swaps) (a)
Cost of sales
 

 
 

 

 
 
(13,951
)
Total derivatives
 
 
$
(1,001
)
 
 
$
2,041

 
$
6,650

 
 
$
(8,775
)
__________
(a)
Related to derivative transactions with a related party.
Offsetting Assets and Liabilities
Alon's derivative financial instruments are subject to master netting arrangements to manage counterparty credit risk associated with derivatives, however, Alon does not offset on its consolidated balance sheets the fair value amounts recorded for derivative instruments under these agreements.
The following table presents offsetting information regarding Alon's derivatives by type of transaction as of June 30, 2013 and December 31, 2012:
 
Gross Amounts of Recognized Assets (Liabilities)
 
Gross Amounts offset in the Statement of Financial Position
 
Net Amounts of Assets (Liabilities) Presented in the Statement of Financial Position
 
Gross Amounts Not offset in the Statement of Financial Position
 
Net Amount
 
 
 
Financial Instruments
 
Cash Collateral Pledged
 
As of June 30, 2013
 
 
 
 
 
 
 
 
 
 
 
Commodity Derivative Assets:
 
 
 
 
 
 
 
 
 
 
Futures & forwards
$
909

 
$

 
$
909

 
$
(728
)
 
$

 
$
181

Commodity Derivative Liabilities:
 
 
 
 
 
 
 
 
 
 
Futures & forwards
(728
)
 

 
(728
)
 
728

 

 

 
 
 
 
 
 
 
 
 
 
 
 
As of December 31, 2012
 
 
 
 
 
 
 
 
 
 
 
Commodity Derivative Assets:
 
 
 
 
 
 
 
 
 
 
Futures & forwards
$
2,365

 
$

 
$
2,365

 
$

 
$

 
$
2,365

(4)
Inventories
Alon's inventories (including inventory consigned to others) are stated at the lower of cost or market. Cost is determined under the last-in, first-out (LIFO) method for crude oil, refined products and blendstock inventories. Materials and supplies are stated at average cost.
Carrying value of inventories consisted of the following:
 
June 30,
2013
 
December 31,
2012
Crude oil, refined products and blendstocks
$
20,792

 
$
24,661

Crude oil inventory consigned to others
23,625

 
23,086

Materials and supplies
9,589

 
9,287

Total inventories
$
54,006

 
$
57,034

Market values of crude oil, refined products and blendstock inventories exceeded LIFO costs by $21,111 and $12,477 at June 30, 2013 and December 31, 2012, respectively.

7

Table of Contents
ALON USA PARTNERS, LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited, dollars in thousands except as noted)


(5)
Inventory Financing Agreement
Alon has entered into a Supply and Offtake Agreement and other associated agreements (together the “Supply and Offtake Agreement”), with J. Aron & Company (“J. Aron”). Pursuant to the Supply and Offtake Agreement, (i) J. Aron agreed to sell to Alon, and Alon agreed to buy from J. Aron, at market prices, crude oil for processing at the Big Spring refinery and (ii) Alon agreed to sell, and J. Aron agreed to buy, at market prices, certain refined products produced at the Big Spring refinery.
The Supply and Offtake Agreement also provided for the sale, at market prices, of Alon's crude oil and certain refined product inventories to J. Aron, the lease to J. Aron of crude oil and refined product storage facilities, and to identify prospective purchasers of refined products on J. Aron's behalf. The Supply and Offtake Agreement was amended in February 2013 and has an initial term that expires in May 2019. J. Aron may elect to terminate the Supply and Offtake Agreement prior to the expiration of the initial term beginning in May 2016 and upon each anniversary thereof, on six months prior notice. Alon may elect to terminate in May 2018 on six months prior notice.
Following expiration or termination of the Supply and Offtake Agreement, Alon is obligated to purchase the crude oil and refined product inventories then owned by J. Aron and located at the Big Spring refinery.
At June 30, 2013 and December 31, 2012, Alon had current payables to J. Aron for purchases of $213 and $16,038, respectively, non-current liabilities related to the original financing of $33,440 and $31,842, respectively, and a consignment inventory receivable representing a deposit paid to J. Aron of $6,290 and $6,290, respectively.
Additionally, Alon had current payables of $692 and current receivables of $4,136 at June 30, 2013 and December 31, 2012, respectively, for forward commitments related to month-end consignment inventory target levels differing from projected levels and the associated pricing with these inventory level differences.
(6)
Property, Plant and Equipment, Net
Property, plant and equipment, net consisted of the following:
 
June 30,
2013
 
December 31,
2012
Refining facilities
$
660,946

 
$
652,910

Less accumulated depreciation
(186,954
)
 
(169,849
)
Property, plant and equipment, net
$
473,992

 
$
483,061

(7)
Additional Financial Information
The tables that follow provide additional financial information related to the consolidated financial statements:
(a)
Other Assets, Net
 
June 30,
2013
 
December 31,
2012
Deferred debt issuance costs
$
8,664

 
$
9,449

Receivable from supply agreements
6,290

 
6,290

Deferred turnaround and chemical catalyst cost
7,162

 
7,622

Other
8,105

 
8,460

Total other assets
$
30,221

 
$
31,821


8

Table of Contents
ALON USA PARTNERS, LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited, dollars in thousands except as noted)


(b)
Accrued Liabilities and Other Non-Current Liabilities
 
June 30,
2013
 
December 31,
2012
Accrued Liabilities:
 
 
 
Taxes other than income taxes, primarily excise taxes
$
23,091

 
$
28,112

Accrued finance charges
1,281

 
1,927

Environmental accrual
831

 
831

RINs obligation
8,016

 

Other
10,400

 
11,348

Total accrued liabilities
$
43,619

 
$
42,218

 
 
 
 
Other Non-Current Liabilities:
 
 
 
Consignment inventory
$
33,440

 
$
31,842

Environmental accrual (Note 11)
5,816

 
5,516

Asset retirement obligations
1,930

 
1,890

Other
2,799

 
2,799

Total other non-current liabilities
$
43,985

 
$
42,047

(8)
Indebtedness
Debt consisted of the following:
 
June 30,
2013
 
December 31,
2012
Term loan credit facility
$
245,312

 
$
246,311

Revolving credit facility

 
49,000

Total debt
245,312

 
295,311

Less current portion
(2,500
)
 
(2,500
)
Total long-term debt
$
242,812

 
$
292,811

Outstanding letters of credit under the revolving credit facility were $100,528 and $58,759 at June 30, 2013 and December 31, 2012, respectively.
Alon's revolving credit facility contains certain restrictive covenants, including maintenance financial covenants. At June 30, 2013, Alon was in compliance with these maintenance financial covenants.
(9)
Partners’ Equity (per unit in dollars)
Cash Distributions. On March 1, 2013, the Partnership paid a cash distribution of $35,626, or $0.57 per unit, for the period of November 27, 2012 through and including December 31, 2012.
On May 15, 2013, the Partnership paid a cash distribution of $92,503, or $1.48 per unit, for the period of January 1, 2013 through and including March 31, 2013.
Restricted Units. During the six months ended June 30, 2013, Alon granted awards totaling 2,467 restricted common units at an average grant date price of $20.27 per unit to non-employee directors of the General Partner. The restricted common units granted to the non-employee directors vest over a period of three years, assuming continued service at vesting.
(10)
Related-Party Transactions
Sales and Receivables
Sales to related parties include motor fuels and asphalt sold to other Alon Energy operations at prices substantially determined by market commodity pricing information. These sales are included in net sales in the consolidated statements of operations. Accounts receivable from related parties include sales of motor fuels and are shown separately on the consolidated balance sheets.

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ALON USA PARTNERS, LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited, dollars in thousands except as noted)


Costs Allocated from Alon Energy
(a)
Corporate Overhead Allocations
Alon is a subsidiary of Alon Energy and is operated as a component of the integrated operations of Alon Energy and its other subsidiaries. As such, the executive officers of Alon Energy, who are employed by another subsidiary of Alon Energy, also serve as executive officers of the General Partner and Alon Energy's other subsidiaries. Alon Energy performs general corporate and administrative services and functions for Alon and Alon Energy's other subsidiaries, which include accounting, treasury, cash management, tax, information technology, insurance administration and claims processing, legal, environmental, risk management, audit, payroll and employee benefit processing and internal audit services. Alon Energy allocates the expenses actually incurred in performing these services to Alon and to its other subsidiaries based primarily on the estimated amount of time the individuals performing such services devote to Alon's business affairs relative to the amount of time they devote to the business affairs of Alon Energy's other subsidiaries. The management of Alon Energy and the General Partner consider these allocations to be reasonable. Alon records the amount of such allocations to its consolidated financial statements as selling, general and administrative expenses. Alon's share of Alon Energy's selling, general and administrative expenses were $3,529 and $3,263, for the three months ended June 30, 2013 and 2012, respectively, and $6,444 and $6,779 for the six months ended June 30, 2013 and 2012, respectively.
(b)
Labor Costs
Alon has no employees and, as a result, actual employee expense costs for Alon Energy employees working in Alon's operations have been allocated and recorded as payroll expense and included in direct operating expenses and selling, general and administrative expenses within the consolidated statements of operations. Alon's share of Alon Energy's employee expense costs included in direct operating expenses were $5,650 and $5,818 for the three months ended June 30, 2013 and 2012, respectively, and $11,958 and $11,405 for the six months ended June 30, 2013 and 2012, respectively.
(c)
Insurance Costs
Insurance costs related to the Big Spring refinery and wholesale marketing operations are allocated to Alon by Alon Energy based on estimated insurance premiums on a stand-alone basis relative to Alon Energy's total insurance premium. Insurance costs included in direct operating expenses was $2,658 and $2,569 for the three months ended June 30, 2013 and 2012, respectively, and $5,262 and $5,162 for the six months ended June 30, 2013 and 2012, respectively.
Distributions
On March 1, 2013, the Partnership paid a cash distribution for the period of November 27, 2012 through and including December 31, 2012 of $35,626, of which $29,070 was paid to Alon Energy. On May 15, 2013, the Partnership paid a cash distribution for the period of January 1, 2013 through and including March 31, 2013 of $92,503, of which $75,480 was paid to Alon Energy.
During the six months ended June 30, 2012, the Predecessor made net cash payments to Alon Energy of $216,886.
On August 5, 2013, the Board of the General Partner declared a cash distribution of approximately $44,375, of which $36,210 will be paid to Alon Energy.
(11)
Commitments and Contingencies
(a)
Commitments
In the normal course of business, Alon has long-term commitments to purchase, at market prices, utilities such as natural gas, electricity and water for use by the refinery, terminals and pipelines. Alon is also party to various refined product and crude oil supply and exchange agreements. These agreements are typically short-term in nature or provide terms for cancellation.
(b)
Contingencies
Alon is involved in various legal actions arising in the ordinary course of business. Alon believes the ultimate disposition of these matters will not have a material effect on Alon's financial position, results of operations or liquidity.

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ALON USA PARTNERS, LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited, dollars in thousands except as noted)


(c)
Environmental
Alon is subject to loss contingencies pursuant to federal, state, and local environmental laws and regulations. These laws and regulations govern the discharge of materials into the environment and may require Alon to incur future obligations to investigate the effects of the release or disposal of certain petroleum, chemical, and mineral substances at various sites; to remediate or restore these sites; to compensate others for damage to property and natural resources and for remediation and restoration costs. These contingent obligations relate to sites owned by Alon and its past or present operations. Alon is currently participating in environmental investigations, assessments and cleanups pertaining to the refinery, pipelines and terminals. Alon may in the future be involved in additional environmental investigations, assessments and cleanups. The magnitude of future costs are unknown and will depend on factors such as the nature and contamination at many sites, the timing, extent and method of the remedial actions which may be required, and the determination of Alon's liability in proportion to other responsible parties.
Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated. Substantially all amounts accrued are expected to be paid out over the next 15 years. The level of future expenditures for environmental remediation obligations is impossible to determine with any degree of reliability.
Alon has accrued environmental remediation obligations of $6,647 ($831 accrued liability and $5,816 non-current liability) at June 30, 2013, and $6,347 ($831 accrued liability and $5,516 non-current liability) at December 31, 2012.
(12)
Subsequent Event
Distribution Declared
On August 5, 2013, the Board of the General Partner declared a cash distribution to the Partnership's common unitholders for the period April 1, 2013 through and including June 30, 2013 of $0.71 per unit, which will result in total distributions in the amount of approximately $44,375. The cash distribution will be paid on August 23, 2013 to unitholders of record at the close of business on August 16, 2013.

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ITEM 2.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
References in this report to the "Predecessor," "we," "our," "us" or like terms, when used in a historical context (periods prior to November 26, 2012) refers to Alon USA Partners, LP Predecessor, our predecessor for accounting purposes. References when used in the present tense or prospectively (after November 26, 2012) refer to Alon USA Partners, LP and its subsidiaries, also referred to as the "Partnership" or "Alon." Unless the context otherwise requires, references in this report to "Alon Energy" refers to Alon USA Energy, Inc. and any of its subsidiaries other than the Partnership, its subsidiaries and its general partner.
The following discussion of our financial condition and results of operations should be read in conjunction with the audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2012.
Forward-Looking Statements
Certain statements contained in this report and other materials we file with the SEC, or in other written or oral statements made by us, other than statements of historical fact, are “forward-looking statements” as defined in the Private Securities Litigation Reform Act of 1995. Forward-looking statements relate to matters such as our industry, business strategy, goals and expectations concerning our market position, future operations, margins, profitability, capital expenditures, liquidity and capital resources and other financial and operating information. We have used the words “anticipate,” “assume,” “believe,” “budget,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “plan,” “potential,” “predict,” “project,” “will,” “future” and similar terms and phrases to identify forward-looking statements.
Forward-looking statements reflect our current expectations of future events, results or outcomes. These expectations may or may not be realized. Some of these expectations may be based upon assumptions or judgments that prove to be incorrect. In addition, our business and operations involve numerous risks and uncertainties, many of which are beyond our control, which could result in our expectations not being realized or otherwise materially affect our financial condition, results of operations and cash flows.
Actual events, results and outcomes may differ materially from our expectations due to a variety of factors. Although it is not possible to identify all of these factors, they include, among others, the following:
changes in general economic conditions and capital markets;
changes in the underlying demand for our products;
the availability, costs and price volatility of crude oil, other refinery feedstocks and refined products;
changes in the spread between West Texas Intermediate ("WTI") crude oil and West Texas Sour ("WTS") crude oil;
the effects of transactions involving forward contracts and derivative instruments;
actions of customers and competitors;
termination of our Supply and Offtake Agreement with J. Aron & Company (“J. Aron”), under which J. Aron is our largest supplier of crude oil and our largest customer of refined products. Additionally, we are obligated to repurchase all consigned inventories and certain other inventories upon termination of the Supply and Offtake Agreement;
changes in fuel and utility costs incurred by our refinery;
disruptions due to equipment interruption, pipeline disruptions or failure at our or third-party facilities;
the execution of planned capital projects;
adverse changes in the credit ratings assigned to our trade credit and debt instruments;
the effects of and cost of compliance with the Renewable Fuel Standard, including the availability, cost and price volatility of Renewable Identification Numbers ("RINs");
the effects and cost of compliance with current and future state and federal environmental, economic, safety and other laws, policies and regulations;
operating hazards, natural disasters, casualty losses and other matters beyond our control;
the effect of any national or international financial crisis on our business and financial condition; and
the other factors discussed in our Annual Report on Form 10-K for the year ended December 31, 2012 under the caption “Risk Factors.”

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Any one of these factors or a combination of these factors could materially affect our future results of operations and could influence whether any forward-looking statements ultimately prove to be accurate. Our forward-looking statements are not guarantees of future performance, and actual results and future performance may differ materially from those suggested in any forward-looking statements. We do not intend to update these statements unless we are required by the securities laws to do so.
Company Overview
On November 26, 2012, the Partnership completed its initial public offering (the "Offering") of 11,500,000 common units representing limited partner interests. After completion of the Offering, Alon Energy contributed to the Partnership its equity interests in Alon USA, LP and Alon USA Refining, Inc. Prior to completion of the Offering, the assets, liabilities and results of operations of the aforementioned assets are related to Alon USA Partners, LP Predecessor ("Predecessor"), our predecessor for accounting purposes.
We are a Delaware limited partnership formed in August 2012 by Alon USA Energy, Inc. (NYSE: ALJ) (“Alon Energy”) to own, operate and grow our strategically located refining and petroleum products marketing business. Our integrated downstream business operates primarily in the South Central and Southwestern regions of the United States. We own and operate a crude oil refinery in Big Spring, Texas with total crude oil throughput capacity of approximately 70,000 barrels per day (“bpd”), which we refer to as our Big Spring refinery. We refine crude oil into finished products, which we market primarily in West Texas, Central Texas, Oklahoma, New Mexico and Arizona through our wholesale distribution network to both Alon Energy’s retail convenience stores and third-party distributors.
We sell refined products in both the wholesale rack and bulk markets. We focus our marketing of transportation fuels on portions of Texas, Oklahoma, New Mexico and Arizona through our physically-integrated refining and distribution system. We distribute fuel products through a product pipeline and terminal network of pipelines and terminals that we own or access through leases or long-term throughput agreements.
Second Quarter Operational and Financial Highlights
Operating income for the second quarter of 2013 was $54.8 million, compared to $111.1 million in the same period last year. Our operational and financial highlights for the second quarter of 2013 include the following:
Big Spring refinery throughput for the second quarter of 2013 averaged 72,124 bpd compared to 64,558 bpd for the second quarter of 2012. Throughput for the second quarter of 2012 was impacted by downtime for the planned regeneration of our reformer catalyst and replacement of several catalyst beds during the period.
Operating margin at the Big Spring refinery was $16.21 per barrel for the second quarter of 2013 compared to $25.79 per barrel for the same period in 2012. This decrease in operating margin is primarily due to lower Gulf Coast 3/2/1 crack spreads and a narrowing of the WTI to WTS spread.
The average Gulf Coast 3/2/1 crack spread was $21.17 per barrel for the second quarter of 2013 compared to $26.04 per barrel for the second quarter of 2012. The average WTI to WTS spread for the second quarter of 2013 was $0.36 per barrel compared to $5.36 per barrel for the same period in 2012.
RINs costs for the three and six months ended June 30, 2013 were $8.0 million. We were not subject to the Renewable Fuel Standard requirements in 2012, which resulted in RINs carryforward credits. These 2012 RINs carryforward credits were used to offset our entire RINs obligation, net of RINs generated, during the three months ended March 31, 2013.
Major Influences on Results of Operations
Earnings and cash flow are primarily affected by the difference between refined product prices and the prices for crude oil and other feedstocks. These prices depend on numerous factors beyond our control, including the supply of, and demand for, crude oil, gasoline and other refined products which, in turn, depend on, among other factors, changes in domestic and foreign economies, weather conditions, domestic and foreign political affairs, production levels, the availability of imports, the marketing of competitive fuels and government regulation. While our sales and operating revenues fluctuate significantly with movements in crude oil and refined product prices, it is the spread between crude oil and refined product prices, and not necessarily fluctuations in those prices, that affect our earnings.
In order to measure our operating performance, we compare our per barrel refinery operating margin to certain industry benchmarks. We calculate this margin for the Big Spring refinery by dividing the refinery’s gross margin by its throughput volumes. Gross margin is the difference between net sales and cost of sales.
The Big Spring refinery operating margin is compared to the Gulf Coast 3/2/1 crack spread that is intended to approximate the refinery's crude slate and product yield. The Gulf Coast 3/2/1 crack spread is calculated assuming that three barrels of WTI

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crude oil are converted, or cracked, into two barrels of Gulf Coast conventional gasoline and one barrel of Gulf Coast ultra-low sulfur diesel.
Our Big Spring refinery is capable of processing substantial volumes of sour crude oil, which has historically cost less than intermediate and sweet crude oils. We measure the cost advantage of refining sour crude oil by calculating the difference between the value of Cushing WTI crude oil and the value of Midland WTS, a medium, sour crude oil. We refer to this differential as the WTI/WTS, or sweet/sour, spread. A widening of the sweet/sour spread can favorably influence the operating margin for our Big Spring refinery.
Our results of operations are also significantly affected by our refinery's operating costs, particularly the cost of natural gas used for fuel and the cost of electricity. Natural gas prices have historically been volatile. Typically, electricity prices fluctuate with natural gas prices.
Demand for gasoline products is generally higher during summer months than during winter months due to seasonal increases in highway traffic. As a result, our operating results for the first and fourth calendar quarters are generally lower than those for the second and third calendar quarters. The effects of seasonal demand for gasoline are partially offset by seasonality in demand for diesel, which in our region is generally higher in winter months as east-west trucking traffic moves south to avoid winter conditions on northern routes.
Safety, reliability and the environmental performance of our refinery is critical to our financial performance. The financial impact of planned downtime, such as a turnaround or major maintenance project, is mitigated through a diligent planning process that considers expectations for product availability, margin environment and the availability of resources to perform the required maintenance.
The nature of our business requires us to maintain substantial quantities of crude oil and refined product inventories. Crude oil and refined products are commodities, and we have no control over the changing market value of these inventories. Because our inventory is valued at the lower of cost or market value under the LIFO inventory valuation methodology, price fluctuations generally have little effect on our financial results.
Factors Affecting Comparability
Our financial condition and operating results over the six months ended June 30, 2013 and 2012, have been influenced by the following factor which is fundamental to understanding comparisons of our period-to-period financial performance.
Renewable Fuel Standard
RINs costs for the three and six months ended June 30, 2013 were $8.0 million. We were not subject to the Renewable Fuel Standard requirements in 2012, which resulted in RINs carryforward credits. These 2012 RINs carryforward credits were used to offset our entire RINs obligation, net of RINs generated, during the three months ended March 31, 2013.

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Results of Operations
The period-to-period comparisons of our results of operations have been prepared using the historical periods included in our consolidated financial statements. We refer to our financial statement line items in the explanation of our period-to-period changes in results of operations. Below are general definitions of what those line items include and represent.
Net Sales. Net sales consist principally of sales of refined petroleum products and are mainly affected by refined product prices, changes to the mix of refined products produced and volume changes caused by operations.
Cost of Sales. Cost of sales primarily includes crude oil, other raw materials and transportation costs.
Direct Operating Expenses. Direct operating expenses include costs associated with the actual operations of the refinery and terminals, such as energy and utility costs, routine maintenance, labor, insurance and environmental compliance costs. Environmental compliance costs, including monitoring and routine maintenance, are expensed as incurred. Substantially all of the operating costs associated with our crude oil and product pipelines are considered to be transportation costs and are reflected in cost of sales in the consolidated statements of operations.
Selling, General and Administrative Expenses. Selling, general and administrative expenses, or SG&A, primarily include corporate overhead costs and marketing expenses.
Depreciation and Amortization. Depreciation and amortization represents an allocation to expense within the consolidated statements of operations of the carrying value of capital assets. The value is allocated based on the straight-line method over the estimated useful life of the related asset. Depreciation and amortization also includes deferred turnaround and catalyst replacement costs. Turnaround and catalyst replacement costs are currently deferred and amortized on a straight-line basis beginning the month after the completion of the turnaround and ending immediately prior to the next scheduled turnaround.
Operating Income. Operating income represents our net sales less our total operating costs and expenses.
Interest Expense. Interest expense includes interest expense, letters of credit, financing costs associated with crude oil purchases, fees, and amortization of both original issuance discount and deferred debt issuance costs but excludes capitalized interest.

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ALON USA PARTNERS, LP AND SUBSIDIARIES CONSOLIDATED
Summary Financial Tables. The following tables provide summary financial data and selected key operating statistics for the three and six months ended June 30, 2013 and 2012. The following data should be read in conjunction with our consolidated financial statements and the notes thereto included elsewhere in this Form 10-Q. All information in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” except for Balance Sheet data as of December 31, 2012 is unaudited.
 
For the Three Months Ended
 
For the Six Months Ended
 
June 30,
 
June 30,
 
2013
 
 
2012
 
2013
 
 
2012
 
 
 
 
Predecessor
 
 
 
 
Predecessor
 
(dollars in thousands, except per unit data, per barrel data and pricing statistics)
STATEMENTS OF OPERATIONS DATA: (A)
 
 
 
 
 
 
 
 
 
Net sales (1)
$
865,694

 
 
$
823,769

 
$
1,669,861

 
 
$
1,708,043

Operating costs and expenses:
 
 
 
 
 
 
 
 
 
Cost of sales
767,322

 
 
672,270

 
1,417,525

 
 
1,460,164

Direct operating expenses
27,314

 
 
25,073

 
57,736

 
 
47,743

Selling, general and administrative expenses
5,065

 
 
3,909

 
12,730

 
 
7,754

Depreciation and amortization
11,243

 
 
11,424

 
23,307

 
 
23,390

Total operating costs and expenses
810,944

 
 
712,676

 
1,511,298

 
 
1,539,051

Operating income
54,750

 
 
111,093

 
158,563

 
 
168,992

Interest expense
(8,970
)
 
 
(5,683
)
 
(18,362
)
 
 
(10,757
)
Interest expense - related parties

 
 
(4,266
)
 

 
 
(8,533
)
Other income (loss), net
14

 
 
(4
)
 
18

 
 
17

Income before state income tax expense
45,794

 
 
101,140

 
140,219

 
 
149,719

State income tax expense
473

 
 
917

 
1,373

 
 
1,420

Net income
$
45,321

 
 
$
100,223

 
$
138,846

 
 
$
148,299

Earnings per unit
$
0.73

 
 
 
 
$
2.22

 
 
 
Weighted average common units outstanding (in thousands)
62,502

 
 
 
 
62,502

 
 
 
CASH FLOW DATA:
 
 
 
 
 
 
 
 
 
Net cash provided by (used in):
 
 
 
 
 
 
 
 
 
Operating activities
$
(13,403
)
 
 
$
143,668

 
$
153,243

 
 
$
187,143

Investing activities
(7,257
)
 
 
(11,823
)
 
(13,976
)
 
 
(19,104
)
Financing activities
(143,128
)
 
 
(126,105
)
 
(178,584
)
 
 
(262,286
)
OTHER DATA:
 
 
 
 
 
 
 
 
 
Adjusted EBITDA (2)
$
66,007

 
 
$
122,513

 
$
181,888

 
 
$
192,399

Capital expenditures
6,216

 
 
5,820

 
9,157

 
 
11,042

Capital expenditures for turnaround and chemical catalyst
1,041

 
 
6,003

 
4,819

 
 
8,062

KEY OPERATING STATISTICS:
 
 
 
 
 
 
 
 
 
Per barrel of throughput:
 
 
 
 
 
 
 
 
 
Refinery operating margin (3)
$
16.21

 
 
$
25.79

 
$
21.85

 
 
$
20.32

Refinery direct operating expense (4)
4.16

 
 
4.27

 
4.85

 
 
3.92

PRICING STATISTICS:
 
 
 
 
 
 
 
 
 
Crack spreads (per barrel):
 
 
 
 
 
 
 
 
 
Gulf Coast (WTI) 3/2/1
$
21.17

 
 
$
26.04

 
$
24.76

 
 
$
25.41

WTI crude oil (per barrel)
$
94.20

 
 
$
93.45

 
$
94.23

 
 
$
98.23

Crude oil differentials (per barrel):
 
 
 
 
 
 
 
 
 
WTI less WTS
$
0.36

 
 
$
5.36

 
$
5.86

 
 
$
3.76

Product price (dollars per gallon):
 
 
 
 
 
 
 
 
 
Gulf Coast unleaded gasoline
$
2.69

 
 
$
2.80

 
$
2.77

 
 
$
2.89

Gulf Coast ultra-low sulfur diesel
2.86

 
 
2.95

 
2.97

 
 
3.05

Natural gas (per MMBtu)
4.02

 
 
2.35

 
3.76

 
 
2.43


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June 30,
2013
 
December 31,
2012
BALANCE SHEET DATA (end of period):
(dollars in thousands)
Cash and cash equivalents
$
26,684

 
$
66,001

Working capital
(24,973
)
 
1,702

Total assets
729,815

 
763,423

Total debt
245,312

 
295,311

Total partners' equity
192,443

 
181,726

THROUGHPUT AND PRODUCTION DATA:
For the Three Months Ended
 
For the Six Months Ended
June 30,
 
June 30,
 
2013
 
 
2012
 
2013
 
 
2012
 
 
 
 
 
 
Predecessor
 
 
 
 
 
 
Predecessor
 
bpd
 
%
 
 
bpd
 
%
 
bpd
 
%
 
 
bpd
 
%
Refinery throughput:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
WTS crude
53,627

 
74.4

 
 
52,250

 
81.0

 
49,446

 
75.1

 
 
53,898

 
80.4

WTI crude
17,180

 
23.8

 
 
10,738

 
16.6

 
14,380

 
21.8

 
 
11,472

 
17.1

Blendstocks
1,317

 
1.8

 
 
1,570

 
2.4

 
2,009

 
3.1

 
 
1,665

 
2.5

Total refinery throughput (5)
72,124

 
100.0

 
 
64,558

 
100.0

 
65,835

 
100.0

 
 
67,035

 
100.0

Refinery production:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gasoline
35,057

 
48.7

 
 
30,885

 
47.8

 
32,436

 
49.4

 
 
33,012

 
49.2

Diesel/jet
24,748

 
34.4

 
 
21,242

 
32.9

 
22,038

 
33.6

 
 
21,739

 
32.5

Asphalt
4,453

 
6.2

 
 
4,041

 
6.2

 
3,909

 
6.0

 
 
4,288

 
6.4

Petrochemicals
4,628

 
6.4

 
 
3,838

 
5.9

 
4,179

 
6.4

 
 
3,988

 
6.0

Other
3,088

 
4.3

 
 
4,655

 
7.2

 
3,029

 
4.6

 
 
3,921

 
5.9

Total refinery production (6)
71,974

 
100.0

 
 
64,661

 
100.0

 
65,591

 
100.0

 
 
66,948

 
100.0

Refinery utilization (7)
 
 
101.2
%
 
 
 
 
98.9
%
 
 
 
97.1
%
 
 
 
 
97.8
%
(A)
Earnings per unit information is not presented for the three and six months ended June 30, 2012 as there was no common equity or potential common equity publicly traded during that period and therefore is not required by Financial Accounting Standards Board ("FASB") Accounting Standards Codification ("ASC") topic 260, Earnings per share.
_____________________
(1)
Includes sales to related parties of $156,043 and $148,171 for the three months ended June 30, 2013 and 2012, respectively, and $297,942 and $298,734 for the six months ended June 30, 2013 and 2012, respectively.
(2)
Adjusted EBITDA represents earnings before state income tax expense, interest expense, depreciation and amortization and gain on disposition of assets. Adjusted EBITDA is not a recognized measurement under GAAP; however, the amounts included in Adjusted EBITDA are derived from amounts included in our consolidated financial statements. Our management believes that the presentation of Adjusted EBITDA is useful to investors because it is frequently used by securities analysts, investors, and other interested parties in the evaluation of companies in our industry. In addition, our management believes that Adjusted EBITDA is useful in evaluating our operating performance compared to that of other companies in our industry because the calculation of Adjusted EBITDA generally eliminates the effects of state income tax expense, interest expense, gain on disposition of assets and the accounting effects of capital expenditures and acquisitions, items that may vary for different companies for reasons unrelated to overall operating performance.
Adjusted EBITDA has limitations as an analytical tool, and you should not consider it in isolation, or as a substitute for analysis of our results as reported under GAAP. Some of these limitations are:
Adjusted EBITDA does not reflect our cash expenditures or future requirements for capital expenditures or contractual commitments;
Adjusted EBITDA does not reflect the interest expense or the cash requirements necessary to service interest or principal payments on our debt;
Adjusted EBITDA does not reflect changes in or cash requirements for our working capital needs; and

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Our calculation of Adjusted EBITDA may differ from EBITDA calculations of other companies in our industry, limiting its usefulness as a comparative measure.
Because of these limitations, Adjusted EBITDA should not be considered a measure of discretionary cash available to us to invest in the growth of our business. We compensate for these limitations by relying primarily on our GAAP results and using Adjusted EBITDA only supplementally.
The following table reconciles net income to Adjusted EBITDA for the three and six months ended June 30, 2013 and 2012, respectively:
 
For the Three Months Ended
 
For the Six Months Ended
 
June 30,
 
June 30,
 
2013
 
 
2012
 
2013
 
 
2012
 
 
 
 
Predecessor
 
 
 
 
Predecessor
 
(dollars in thousands)
Net income
$
45,321

 
 
$
100,223

 
$
138,846

 
 
$
148,299

State income tax expense
473

 
 
917

 
1,373

 
 
1,420

Interest expense
8,970

 
 
5,683

 
18,362

 
 
10,757

Interest expense - related parties

 
 
4,266

 

 
 
8,533

Depreciation and amortization
11,243

 
 
11,424

 
23,307

 
 
23,390

Adjusted EBITDA
$
66,007

 
 
$
122,513

 
$
181,888

 
 
$
192,399

(3)
Refinery operating margin is a per barrel measurement calculated by dividing the margin between net sales and cost of sales by the refinery's throughput volumes. Industry-wide refining results are driven and measured by the margins between refined product prices and the prices for crude oil, which are referred to as crack spreads. We compare our refinery operating margin to these crack spreads to assess our operating performance relative to other participants in our industry.
The refinery operating margin excludes charges of $8,016 related to RINs obligation for the three and six months ended June 30, 2013.
(4)
Refinery direct operating expense is a per barrel measurement calculated by dividing direct operating expenses by total throughput volumes.
(5)
Total refinery throughput represents the total barrels per day of crude oil and blendstock inputs in the refinery production process.
(6)
Total refinery production represents the barrels per day of various refined products produced from processing crude and other refinery feedstocks through the crude units and other conversion units.
(7)
Refinery utilization represents average daily crude oil throughput divided by crude oil capacity, excluding planned periods of downtime for maintenance and turnarounds.

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Three Months Ended June 30, 2013 Compared to the Three Months Ended June 30, 2012
Net Sales. Net sales for the three months ended June 30, 2013 were $865.7 million, compared to $823.8 million for the three months ended June 30, 2012, an increase of $41.9 million. This increase was primarily due to higher refinery throughput, partially offset by lower refined product prices in the three months ended June 30, 2013 compared to the same period last year. Refinery throughput for the three months ended June 30, 2013 was 72,124 bpd compared to 64,558 bpd for the three months ended June 30, 2012, an increase of 11.7%. Throughput for the three months ended June 30, 2012 was impacted by downtime for the planned regeneration of our reformer catalyst and replacement of several catalyst beds during the period. The average per gallon price of Gulf Coast gasoline for the three months ended June 30, 2013 decreased $0.11, or 3.9%, to $2.69, compared to $2.80 for the three months ended June 30, 2012. The average per gallon price of Gulf Coast ultra-low sulfur diesel for the three months ended June 30, 2013 decreased $0.09, or 3.1%, to $2.86, compared to $2.95 for the three months ended June 30, 2012.
Cost of Sales. Cost of sales for the three months ended June 30, 2013 were $767.3 million, compared to $672.3 million for the three months ended June 30, 2012, an increase of $95.0 million. This increase was primarily due to higher refinery throughput and higher crude oil prices. The average price of WTI for the three months ended June 30, 2013 was $94.20, which was $0.75, or 0.8%, higher than the $93.45 per barrel average for the three months ended June 30, 2012. Additionally, the average price of WTS was higher as the differential to WTI narrowed to $0.36 per barrel, a decrease of 93.3%, for the three months ended June 30, 2013 compared to $5.36 per barrel for the three months ended June 30, 2012.
Direct Operating Expenses. Direct operating expenses for the three months ended June 30, 2013 were $27.3 million, compared to $25.1 million for the three months ended June 30, 2012, an increase of $2.2 million, or 8.8%. This increase was primarily due to higher refinery throughput and higher natural gas prices.
Selling, General and Administrative Expenses. SG&A expenses for the three months ended June 30, 2013 were $5.1 million, compared to $3.9 million for the three months ended June 30, 2012, an increase of $1.2 million, or 30.8% due primarily to higher employee incentive compensation costs.
Depreciation and Amortization. Depreciation and amortization for the three months ended June 30, 2013 was $11.2 million, compared to $11.4 million for the three months ended June 30, 2012, a decrease of $0.2 million, or 1.8%.
Operating Income. Operating income for the three months ended June 30, 2013 was $54.8 million, compared to $111.1 million for the three months ended June 30, 2012, a decrease of $56.3 million. This decrease was primarily due to lower refinery margins resulting from decreased Gulf Coast (WTI) 3/2/1 crack spreads and a narrowed WTI to WTS spread. Refinery operating margin was $16.21 per barrel for the three months ended June 30, 2013, compared to $25.79 per barrel for the three months ended June 30, 2012. The average Gulf Coast (WTI) 3/2/1 crack spread decreased to $21.17 per barrel for the three months ended June 30, 2013, compared to $26.04 per barrel for the three months ended June 30, 2012. Additionally, the WTI to WTS spread narrowed for the three months ended June 30, 2013 to $0.36 per barrel compared to $5.36 per barrel for the three months ended June 30, 2012. Also impacting the operating income was approximately $8.0 million of costs associated with the RINs obligation for the three months ended June 30, 2013.
Interest Expense. Interest expense for the three months ended June 30, 2013 was $9.0 million, compared to total interest expense of $9.9 million, including interest expense to related parties, for the three months ended June 30, 2012, a decrease of $0.9 million. This decrease is primarily due to interest expense incurred on a lower amount of outstanding debt during the three months ended June 30, 2013 as compared to the three months ended June 30, 2012.
Net Income. Net income for the three months ended June 30, 2013 was $45.3 million, compared to $100.2 million for the three months ended June 30, 2012, a decrease of $54.9 million. This decrease was attributable to the factors discussed above.
Six Months Ended June 30, 2013 Compared to the Six Months Ended June 30, 2012
Net Sales. Net sales for the six months ended June 30, 2013 were $1,669.9 million, compared to $1,708.0 million for the six months ended June 30, 2012, a decrease of $38.1 million. This decrease was due to lower refinery throughput and lower refined product prices. Refinery throughput for the six months ended June 30, 2013 was 65,835 bpd compared to 67,035 bpd for the six months ended June 30, 2012, a decrease of 1.8%. The average per gallon price of Gulf Coast gasoline for the six months ended June 30, 2013 decreased $0.12, or 4.2%, to $2.77, compared to $2.89 for the six months ended June 30, 2012. The average per gallon price of Gulf Coast ultra low-sulfur diesel for the six months ended June 30, 2013 decreased $0.08, or 2.6%, to $2.97, compared to $3.05 for the six months ended June 30, 2012.

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Cost of Sales. Cost of sales were $1,417.5 million for the six months ended June 30, 2013, compared to $1,460.2 million for the six months ended June 30, 2012, a decrease of $42.7 million. This decrease was primarily due to decreased refinery throughput and a decrease in crude oil prices. The average price of WTI decreased 4.1% from $98.23 per barrel for the six months ended June 30, 2012, to $94.23 per barrel for the six months ended June 30, 2013. Additionally, the average price of WTS was lower as the differential to WTI widened to $5.86 per barrel for the six months ended June 30, 2013, compared to $3.76 per barrel for the six months ended June 30, 2012.
Direct Operating Expenses. Direct operating expenses for the six months ended June 30, 2013 were $57.7 million, compared to $47.7 million for the six months ended June 30, 2012, an increase of $10.0 million, or 21.0%. This increase was primarily due to higher major maintenance costs, property tax expenses and higher natural gas costs for the six months ended June 30, 2013.
Selling, General and Administrative Expenses. SG&A expenses for the six months ended June 30, 2013 were $12.7 million, compared to $7.8 million for the six months ended June 30, 2012, an increase of $4.9 million, or 62.8%. This increase was primarily due to higher employee incentive compensation costs and marketing expenses for the six months ended June 30, 2013.
Depreciation and Amortization. Depreciation and amortization for the six months ended June 30, 2013 was $23.3 million, compared to $23.4 million for the six months ended June 30, 2012, a decrease of $0.1 million.
Operating Income. Operating income was $158.6 million for the six months ended June 30, 2013, compared to $169.0 million for the six months ended June 30, 2012, a decrease of $10.4 million. This decrease was primarily due to higher direct operating and SG&A expenses, partially offset by higher refinery margins. Refinery operating margin was $21.85 per barrel for the six months ended June 30, 2013, compared to $20.32 per barrel for the six months ended June 30, 2012. This increase in operating margin is primarily due to a widening of the WTI to WTS spread partially offset by lower Gulf Coast (WTI) 3/2/1 crack spreads. The WTI to WTS spread widened 55.9% to $5.86 per barrel for the six months ended June 30, 2013, compared to $3.76 per barrel for the six months ended June 30, 2012. The average Gulf Coast (WTI) 3/2/1 crack spread decreased 2.6% to $24.76 per barrel for the six months ended June 30, 2013, compared to $25.41 per barrel for the six months ended June 30, 2012. Also impacting the operating income was approximately $8.0 million of costs associated with the RINs obligation for the six months ended June 30, 2013.
Interest Expense. Interest expense was $18.4 million for the six months ended June 30, 2013, compared to total interest expense of $19.3 million, including interest expense to related parties, for the six months ended June 30, 2012, a decrease of $0.9 million. This decrease is primarily due to interest expense incurred on a lower amount of outstanding debt during the six months ended June 30, 2013 as compared to the six months ended June 30, 2012.
Net Income. Net income for the six months ended June 30, 2013 was $138.8 million, compared to $148.3 million for the six months ended June 30, 2012, a decrease of $9.5 million. This decrease was attributable to the factors discussed above.
Liquidity and Capital Resources
Our primary sources of liquidity are cash on hand, cash generated from our operating activities, borrowings under our revolving credit facility, inventory supply and offtake arrangement and other credit lines.
We have an agreement with J. Aron for the supply of crude oil that will support the operations of the Big Spring refinery. This arrangement substantially reduces our need to issue letters of credit to support crude oil purchases. In addition, the structure allows us to acquire crude oil without the constraints of a maximum facility size during periods of high crude oil prices.
We believe that the aforementioned sources of funds and other sources of capital available to us will be sufficient to satisfy the anticipated cash requirements associated with our existing operations for at least the next twelve months. However, future capital expenditures and other cash requirements could be higher than we currently expect as a result of various factors. Additionally, our ability to generate sufficient cash from our operating activities depends on our future performance, which is subject to general economic, political, financial, competitive, and other factors beyond our control.

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Cash Flows
The following table sets forth our consolidated cash flows for the six months ended June 30, 2013 and 2012:
 
For the Six Months Ended
 
June 30,
 
2013
 
 
2012
 
 
 
 
Predecessor
 
(dollars in thousands)
Cash provided by (used in):
 
 
 
 
Operating activities
$
153,243

 
 
$
187,143

Investing activities
(13,976
)
 
 
(19,104
)
Financing activities
(178,584
)
 
 
(262,286
)
Net decrease in cash and cash equivalents
$
(39,317
)
 
 
$
(94,247
)
Cash Flows Provided by Operating Activities
Net cash provided by operating activities during the six months ended June 30, 2013 was $153.2 million, compared to $187.1 million during the six months ended June 30, 2012. The reduction in net cash provided by operating activities of $33.9 million was primarily attributable to lower net income after adjusting for non-cash items of $17.8 million, lower cash collected on accounts receivables of $13.2 million, higher cash on reduction of inventories of $24.5 million and lower cash on reduction of accounts payable and accrued liabilities of $27.9 million.
Cash Flows Used In Investing Activities
Net cash used in investing activities was $14.0 million during the six months ended June 30, 2013 compared to $19.1 million during the six months ended June 30, 2012. The reduction in net cash used in investing activities of $5.1 million was primarily due to a decrease in capital expenditures and capital expenditures for turnarounds and catalysts.
Cash Flows Used In Financing Activities
Net cash used in financing activities was $178.6 million during the six months ended June 30, 2013 compared to $262.3 million during the six months ended June 30, 2012. The reduction in net cash used in financing activities of $83.7 million was primarily attributable to lower net payments to equity holders of $88.8 million offset by higher net repayments on our revolving credit facility of $6.0 million.
Indebtedness
Partnership Term Loan Credit Facility. In connection with the Offering, we were assigned $250.0 million of the aggregate principal balance of the Alon USA Term Loan (the “Partnership Term Loan”). The Partnership Term Loan requires principal payments of $2.5 million per annum paid in quarterly installments until maturity in November 2018.
Borrowings under the Partnership Term Loan bear interest at a rate equal to the sum of (i) the Eurodollar rate (with a floor of 1.25% per annum) plus (ii) a margin of approximately 8.00% per annum for a per annum rate of approximately 9.25%, based on current market rates at June 30, 2013.
The Partnership Term Loan is secured by a first priority lien on all of our fixed assets and other specified property, as well as on our general partner interest held by the General Partner, and a second lien on our cash, accounts receivables, inventories and related assets.
The Partnership Term Loan contains restrictive covenants, such as restrictions on liens, mergers, consolidations, sales of assets, additional indebtedness, different businesses, certain lease obligations and certain restricted payments. The Partnership Term Loan does not contain any maintenance financial covenants.
At June 30, 2013, the Partnership Term Loan had an outstanding balance (net of unamortized discount) of $245.3 million.
Revolving Credit Facility. We have a $240.0 million revolving credit facility (the “Revolving Credit Facility”) that will mature in March 2016. The Revolving Credit Facility can be used both for borrowings and the issuance of letters of credit subject to a limit of the lesser of the facility amount or the borrowing base amount under the facility.
Borrowings under the Revolving Credit Facility bear interest at the Eurodollar rate plus 3.50% per annum subject to an overall minimum interest rate of 4.00%.

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The Revolving Credit Facility is secured by (i) a first lien on our cash, accounts receivables, inventories and related assets and (ii) a second lien on our fixed assets.
The Revolving Credit Facility contains certain restrictive covenants, including maintenance financial covenants. At June 30, 2013, we were in compliance with these maintenance financial covenants.
There were no outstanding borrowings under the Revolving Credit Facility at June 30, 2013, which had an outstanding balance of $49.0 million at December 31, 2012. At June 30, 2013 and December 31, 2012, outstanding letters of credit under the Revolving Credit Facility were $100.5 million and $58.8 million, respectively.
Capital Spending
Each year the Board of Directors of our General Partner approves capital projects, including regulatory and planned turnaround projects that our management is authorized to undertake in our annual capital budget. Additionally, at times when conditions warrant or as new opportunities arise, other projects or the expansion of existing projects may be approved. Our total capital expenditure and turnaround/chemical catalyst plan for 2013 is $34.8 million. Approximately $14.0 million has been spent during the six months ended June 30, 2013.
Contractual Obligations and Commercial Commitments
There have been no material changes outside the ordinary course of business from our contractual obligations and commercial commitments detailed in our Annual Report on Form 10-K for the year ended December 31, 2012.
Off-Balance Sheet Arrangements
We have no material off-balance sheet arrangements.
Critical Accounting Policies
We prepare our consolidated financial statements in conformity with GAAP. In order to apply these principles, we must make judgments, assumptions and estimates based on the best available information at the time. Actual results may differ based on the accuracy of the information utilized and subsequent events, some of which we may have little or no control over.
Our critical accounting policies are described under the caption “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies” in our Annual Report on Form 10-K for the year ended December 31, 2012. Certain critical accounting policies that materially affect the amounts recorded in our consolidated financial statements are the use of the LIFO method for valuing certain inventories and the deferral and subsequent amortization of costs associated with major turnarounds and chemical catalysts replacements. No significant changes to these accounting policies have occurred subsequent to December 31, 2012.
New Accounting Standards and Disclosures
New accounting standards if any are disclosed in Note (1) Basis of Presentation included in the consolidated financial statements included in Item 1 of this report.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Changes in commodity prices, purchased fuel prices and interest rates are our primary sources of market risk. Alon Energy's risk management committee oversees all activities associated with the identification, assessment and management of our market risk exposure.
Commodity Price Risk
We are exposed to market risks related to the volatility of crude oil and refined product prices, as well as volatility in the price of natural gas used in our refinery operations. Our financial results can be affected significantly by fluctuations in these prices, which depend on many factors, including demand for crude oil, gasoline and other refined products, changes in the economy, worldwide production levels, worldwide inventory levels and governmental regulatory initiatives. Alon Energy's risk management strategy identifies circumstances in which we may utilize the commodity futures market to manage risk associated with these price fluctuations.
In order to manage the uncertainty relating to inventory price volatility, we have consistently applied a policy of maintaining inventories at or below a targeted operating level. In the past, circumstances have occurred, such as timing of crude oil cargo deliveries, turnaround schedules or shifts in market demand that have resulted in variances between our actual inventory level and our desired target level. Upon the review and approval of Alon Energy's risk management committee, we may utilize the commodity futures market to manage these anticipated inventory variances.
We maintain inventories of crude oil, refined products and blendstocks, the values of which are subject to wide fluctuations in market prices driven by world economic conditions, regional and global inventory levels and seasonal conditions. As of June 30, 2013, we held approximately 0.6 million barrels of crude oil and refined product inventories valued under the LIFO valuation method. Market value exceeded carrying value of LIFO costs by $21.1 million. We refer to this excess as our LIFO reserve. If the market value of these inventories had been $1.00 per barrel lower, our LIFO reserve would have been reduced by $0.6 million.
In accordance with fair value provisions of ASC 825-10, all commodity contracts are recorded at fair value and any changes in fair value between periods is recorded in the profit and loss section of our consolidated financial statements. “Forwards” represent physical trades for which pricing and quantities have been set, but the physical product delivery has not occurred by the end of the reporting period. “Futures” represent trades which have been executed on the New York Mercantile Exchange which have not been closed or settled at the end of the reporting period. A “long” represents an obligation to purchase product and a “short” represents an obligation to sell product.
The following table provides information about our derivative commodity instruments as of June 30, 2013:
Description
 
Contract Volume
 
Wtd Avg Purchase
 
Wtd Avg Sales
 
Contract
 
Market
 
Gain
of Activity
 
(barrels)
 
Price/BBL
 
Price/BBL
 
 Value
 
Value
 
(Loss)
 
 
 
 
 
 
 
 
(in thousands)
Forwards-long (Crude)
 
35,461

 
$
95.49

 
$

 
$
3,386

 
$
3,421

 
$
35

Forwards-long (Gasoline)
 
157,698

 
116.90

 

 
18,434

 
18,029

 
(405
)
Forwards-long (Distillate)
 
107,693

 
123.06

 

 
13,253

 
13,106

 
(147
)
Forwards-short (Jet)
 
(17,731
)
 

 
118.91

 
(2,108
)
 
(2,079
)
 
29

Forwards-short (Slurry)
 
(1,034
)
 

 
88.98

 
(92
)
 
(91
)
 
1

Forwards-long (Catfeed)
 
96,413

 
113.75

 

 
10,967

 
10,753

 
(214
)
Forwards-short (Slop)
 
(11,381
)
 

 
85.80

 
(977
)
 
(985
)
 
(8
)
Forwards-short (Propane)
 
(26,104
)
 

 
34.40

 
(898
)
 
(881
)
 
17

Futures-short (Crude)
 
(155,000
)
 

 
96.17

 
(14,906
)
 
(14,967
)
 
(61
)
Futures-short (Gasoline)
 
(231,000
)
 

 
117.80

 
(27,213
)
 
(26,347
)
 
866

Futures-short (Distillate)
 
(72,000
)
 

 
121.02

 
(8,713
)
 
(8,645
)
 
68

Interest Rate Risk
As of June 30, 2013, our outstanding debt balance of approximately $248.8 million, excluding discounts, was charged interest at the Eurodollar rate (with a floor of 1.25%) plus a margin of 8.00%. An increase of 1% in the Eurodollar rate on indebtedness would have no impact on our interest expense.

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ITEM 4. CONTROLS AND PROCEDURES
(1)
Disclosure controls and procedures.
Our management has evaluated, with the participation of our principal executive and principal financial officers, the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934 as amended (the “Exchange Act”)) as of the end of the period covered by this report, and has concluded that our disclosure controls and procedures are effective to provide reasonable assurance that information required to be disclosed by us in the reports that we file or furnish under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC's rules and forms including, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in the reports that we file or furnish under the Exchange Act is accumulated and communicated to our management, including our principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosures.
The SEC, as required by Section 404 of the Sarbanes-Oxley Act, adopted rules requiring companies to file reports with the SEC to include a management report on such company's internal control over financial reporting in its annual report. In addition, our independent registered public accounting firm must attest to our internal control over financial reporting. Our first Annual Report on Form 10-K did not include a report of management's assessment regarding internal control over financial reporting or an attestation report of our independent registered public accounting firm due to a transition period established by SEC rules applicable to new public companies. Management will be required to provide an assessment of the effectiveness of our internal control over financial reporting as of December 31, 2013.
(2)
Changes in internal control over financial reporting.
There has been no change in our internal control over financial reporting (as described in Rule 13a-15(f) under the Exchange Act) that occurred during our last fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION
ITEM 6. EXHIBITS
Exhibit
 
 
Number
 
Description of Exhibit
10.1
 
Second Amended Revolving Credit Agreement, dated as of May 23, 2013, by and among Alon USA, LP, Israel Discount Bank of New York, Bank Leumi USA and certain other guarantor companies and financial institutions from time to time named therein (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Partnership on May 24, 2013, SEC File No. 001-35742).
31.1
 
Certifications of Chief Executive Officer pursuant to §302 of the Sarbanes-Oxley Act of 2002.
31.2
 
Certifications of Chief Financial Officer pursuant to §302 of the Sarbanes-Oxley Act of 2002.
32.1
 
Certifications of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002.
101
 
The following financial information from Alon USA Partners, LP’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2013, formatted in XBRL (Extensible Business Reporting Language): (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Operations, (iii) Consolidated Statements of Cash Flows and (iv) Notes to the Consolidated Financial Statements.


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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
 
 
Alon USA Partners, LP
 
 
By:  
Alon USA Partners GP, LLC
 
 
 
its general partner
 
 
 
Date:
August 8, 2013
By:  
/s/ David Wiessman
 
 
 
David Wiessman 
 
 
 
Executive Chairman of the Board
 
 
 
 
 
 
 
 
Date:
August 8, 2013
By:  
/s/ Paul Eisman
 
 
 
Paul Eisman
 
 
 
President, Chief Executive Officer and Director
 
 
 
 
 
 
 
 
Date:
August 8, 2013
By:  
/s/ Shai Even
 
 
 
Shai Even 
 
 
 
Senior Vice President and Chief Financial Officer 
 
 
 
(Principal Accounting Officer)

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EXHIBITS
Exhibit
 
 
Number
 
Description of Exhibit
10.1
 
Second Amended Revolving Credit Agreement, dated as of May 23, 2013, by and among Alon USA, LP, Israel Discount Bank of New York, Bank Leumi USA and certain other guarantor companies and financial institutions from time to time named therein (incorporated by reference to Exhibit 10.1 to Form 8-K, filed by the Partnership on May 24, 2013, SEC File No. 001-35742).
31.1
 
Certifications of Chief Executive Officer pursuant to §302 of the Sarbanes-Oxley Act of 2002.
31.2
 
Certifications of Chief Financial Officer pursuant to §302 of the Sarbanes-Oxley Act of 2002.
32.1
 
Certifications of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002.
101
 
The following financial information from Alon USA Partners, LP’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2013, formatted in XBRL (Extensible Business Reporting Language): (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Operations, (iii) Consolidated Statements of Cash Flows and (iv) Notes to the Consolidated Financial Statements.

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